This disclosure relates generally to temperature sensing, and more particularly, to the use of new methodologies for interpreting distributed temperature sensing information.
Fiber optic Distributed Temperature Sensing (DTS) systems were developed in the 1980s to replace thermocouple and thermistor based temperature measurement systems. DTS technology is often based on Optical Time-Domain Reflectometry (OTDR) and utilizes techniques originally derived from telecommunications cable testing. Today DTS provides a cost-effective way of obtaining hundreds, or even thousands, of highly accurate, high-resolution temperature measurements, DTS systems today find widespread acceptance in industries such as oil and gas, electrical power, and process control.
DTS technology has been applied in numerous applications in oil and gas exploration, for example hydraulic fracturing, production, and cementing among others. The collected data demonstrates the temperature profiles as a function of depth and of time during a downhole sequence. The quality of the data is critical for interpreting various fluid movements.
The underlying principle involved in DTS-based measurements is the detection of spontaneous Raman back-scattering. A DTS system launches a primary laser pulse that gives rise to two back-scattered spectral components. A Stokes component that has a lower frequency and higher wavelength content than the launched laser pulse, and an anti-Stokes component that has a higher frequency and lower wavelength than the launched laser pulse. The anti-Stokes signal is usually an order of magnitude weaker than the Stokes signal (at room temperature) and it is temperature sensitive, whereas the Stokes signal is almost entirely temperature independent. Thus, the ratio of these two signals can be used to determine the temperature of the optical fiber at a particular point. The time of flight between the launch of the primary laser pulse and the detection of the back-scattered signal may be used to calculate the spatial location of the scattering event within the fiber.
Artificial lift refers to the use of artificial means to increase the flow of liquids, such as crude oil or water, from a production well. Generally this is achieved by the use of a mechanical device inside the well (known as pump or velocity string) or by decreasing the weight of the hydrostatic column by injecting gas into the liquid some distance down the well. Artificial lift is needed in wells when there is insufficient pressure in the reservoir to lift the produced fluids to the surface, but often used in naturally flowing wells (which do not technically need it) to increase the flow rate above what would flow naturally. The produced fluid can be oil, water or a mix of oil and water, typically mixed with some amount of gas.
Electric Submersible Pumps (ESP) is one of the important devices for artificial lift production. ESP consists of a downhole pump (a series of centrifugal pumps), an electrical motor which transforms the electrical power into kinetic energy to turn the pump, a separator or protector to prevent produced fluids from entering the electrical motor, and an electric power cable that connects the motor to the surface control panel. ESP is a very versatile artificial lift method and can be found in operating environments all over the world. They can handle a very wide range of flow rates (from 200 to 90,000 barrels (14,000 m3) per day) and lift requirements (from virtually zero to 10,000 ft. (3,000 m) of lift). Operators of ESP systems have to monitor the casing fluid level carefully to balance between production and protection. Large production rate requires a large pressure drop from the reservoir to the bottom hole of the well, which lowers the fluid level in the casing. However, the fluid level has to be kept above the ESP to a certain level so that the pump is not starved of the fluid it needs for cooling. If the fluid level is too low, an under-load condition will shut down the pump, potentially leaving the well productionless for hours, while the well fluid level increases as fluids flow from the reservoir into the well and refill the well bore to a safe level above the ESP.
Besides ESP protection, fluid level, playing a role of pressure indicator, can be used for monitoring down hole pressure change to control the production rate. Production optimization attempts to minimize water production rate while maximizing oil and gas rate. Due to different capillary pressure between oil and water and surface tension between formation rock and different fluids like water and oil, flow rate of oil, water and gas is different at different depth of the well under different draw down pressures. By monitoring the down hole pressure, an optimization can be reached to find the highest OWR (oil water ratio). Fluid level detection and monitoring is critical and often done using down hole gauge(s), but other means of fluid level monitoring are desirable especially when calibration or replacement is required of the down-hole pressure gauge.
When DTS fiber is installed along the production well, DTS data is plotted in time-depth scale to monitor the temperature along the wellbore. Besides the production intervals, DTS data can also be used in many other functions. One of them is fluid level detection. However, conventional DTS plots are not able to give a clear profile of the fluid level in time scale. Air and foam above the fluid level causes a much more unstable temperature comparing with the one below the fluid level. Variation of the temperature above the fluid level is however too small to be observed from the DTS plot itself due to its large temperature range as 70 F to 200 F.
There is a need then for better analysis tools to detect fluid level changes.